Mud lift drilling system using ejector assembly in mud return line

ABSTRACT

A method is described for controlling pressure in a wellbore drilled below the bottom of a body of water wherein the wellbore has a fluid outlet in communication with a working fluid inlet of an ejector assembly to return drilling fluid to a drilling platform on the water surface. The method includes pumping drilling fluid into a drill string extending from the drilling platform into the wellbore and at least one of, (i) introducing fluid into a power fluid inlet of the ejector assembly at a rate selected to remove fluid from the wellbore fluid outlet at a selected rate and (ii) operating a controllable flow restriction in a flow path from the wellbore fluid outlet to the working fluid inlet of the ejector assembly, in order to maintain a selected wellbore pressure.

BACKGROUND

This disclosure is related to the field of controlled pressure drillingand “dual gradient” drilling. More particularly the disclosure relatesto apparatus and methods for controlled pressure and/or dual gradientdrilling that use ejector assemblies.

International Application Publication No. WO 2013/0177331 describes amanaged pressure drilling system using a pump in a drilling fluid returnline. The pump may be used to maintain a selected fluid level in adrilling riser disposed above a top of a subsea wellbore, wherein theriser extends from a subsea wellhead at the water bottom to a drillingplatform above the water surface. By suitable operation of the pump, thefluid level may be maintained at a selected elevation at or below thewater surface so that a pressure in the wellbore may be maintained at orbelow the hydrostatic pressure of the fluid column in the riser were itto extend from the bottom of the wellbore to the surface. In the casethe fluid level elevation in the riser is maintained below the surface,the pressure elevation gradient of the fluid in the riser may bedifferent than the fluid pressure elevation gradient of fluid (“mud”)pumped into a drill string used to drill the wellbore below the waterbottom. In other implementations, a riser may be omitted, and drillingfluid being discharged from the wellbore may be returned to the surfaceby a separate return line having a pump therein.

The system shown in the '331 publication cited above is illustrative of“mud lift” drilling systems known in the art. Referring to FIG. 1, whena wellbore is drilled from a bottom supported drilling platform or afloating drilling platform (“drilling rig”) 1 disposed above the surfaceof a body of water, a conductor is first driven into the water bottom orseabed. When drilling a wellbore 15 from a drilling rig 1, drillingfluid may be pumped using a mud pump 26, through an interior conduit ina drill string 16 suspended by a kelly or top drive, down to a drillingtool, which may terminate in a drill bit (not shown) that cuts throughthe sub-bottom formations to lengthen the wellbore 15. The drillingfluid serves several purposes, some of which are to transport drillcuttings out of the borehole, and to maintain fluid pressure in thewellbore 15 to prevent collapse of the wellbore 15 and prevent entry offluids into the wellbore 15 from exposed formations. Efficient transportof drill cuttings requires that the drilling fluid is relativelyviscous. The drilling fluid flows back through an annulus 30 between thewellbore wall, a liner or casing 14 and the drill string 16, and up tothe drilling rig 1, where the drilling fluid may be treated in devices24 for such purposes and conditioned before being pumped back down intothe wellbore 15. In some cases, the combined pressure of pumping and theselected density of the drilling fluid will result in a head of pressureand/or pressure gradient in the wellbore annulus 30 that is undesirable.

By coupling a subsea mud lift pump 20 to the liner 14 near the seabed(or to the wellhead when drilling, e.g., from a floating drillingplatform), the returning drilling fluid can be pumped out of the annulus30 and up to the drilling rig 1 to reduce the fluid pressure in theannulus 30. In some implementations, the annular volume above thewellbore may include a riser that may be partially or completely filledwith drilling fluid and/or with a different riser fluid. The density ofthe riser fluid, if used, may be less than that of the drilling fluid.It is also possible to drill such wellbores without a riser by using arotating control head or rotating diverter coupled to the top of thewellbore (i.e., the wellhead) to seal against the drill string 16.

The drilling fluid pressure existing at the level of the water bottommay be controlled from the drilling rig 1 by selecting the inletpressure to the subsea mud lift pump 20. In riser-type drilling systemsas shown in FIG. 1, the height H₁ of the column of drilling fluid abovethe water bottom depends on the selected inlet pressure of the subseamud lift pump 20, the density of the drilling fluid, the density of theriser fluid and the relative vertical elevation levels of each suchfluid in the riser. The inlet pressure of the subsea mud lift pump 20 isequal to: P=(H₁ γ_(b))+(H₂ γ_(s)) in which γ_(b) represents the densityof the drilling fluid, H₁ represents the height of the drilling fluidcolumn above the pump inlet point, H₂ represents the height of thecolumn of riser fluid, and γ_(s) represent the density of the riserfluid.

H₁ and H₂ together make up the length of the riser section from thewater bottom 8 and in some examples may extend upward to the deck 4 ofthe drilling rig 1. Filling the riser 12 at least in part with a riserfluid allows continuous flow quantity control of the fluid flowing intoand out of the wellbore 15. Thus, it is relatively easy to detect aphenomenon, such as, for example, drilling fluid flowing out of thewellbore 15 into an exposed formation (“lost circulation”). It isfurthermore possible to maintain a substantially constant drilling fluidpressure at the level of the water bottom when the drilling fluiddensity changes. Choosing a different inlet pressure to the subsea mudlift pump will cause the heights H₁ and H₂ to change according to thenew selected subsea mud lift pump 20 inlet pressure. If so desired, theoutlet 17 from the annulus 30 to the subsea mud lift pump 20 can bearranged at a level below the water bottom, by coupling a first pumppipe (not shown in FIG. 1) to the annulus at a level below the waterbottom. In order to prevent the drilling fluid pressure from exceedingan acceptable level (e.g., in the case of a pipe “trip”), the riser 12be provided with a dump valve. A dump valve of this type can be set toopen at a particular pressure for outflow of drilling fluid to the bodyof water. Other examples may omit a dump valve.

As explained above, using a riser to exert part of the hydrostaticpressure on the wellbore annulus is optional, and in otherimplementations the riser may be omitted. Such implementations may use arotating control head or other rotatable sealing device (not shown) toseal the annular space above the top of the wellbore 15 while enablingrotation and axial motion of the drill string 16.

In FIG. 1, reference number 1 denotes the drilling rig comprising asupport structure 2, a deck 4 and a derrick 6. The support structure 2is placed on the water bottom 8 and projects above the surface 10 of thesea. As explained above the deck may also be supported by a floatingplatform (not shown). A riser section 12 of a liner 14 extends from thewater bottom 8 or a subsea wellhead (not shown) up to the deck 4, whilethe liner 14 runs further down into the wellbore 15. The riser section12 is provided with required well head valves (not shown). The drillstring 16 projects from the deck 4 and down through the liner 14. Afirst pump pipe 17 may be coupled to the riser section 12 near the waterbottom 8 via a valve 18 and the opposite end portion of the pump pipe 17is coupled to the intake of the subsea mud lift pump 20. In the presentexample the subsea mud lift pump may be placed near the water bottom 8.A second pump pipe 22 runs from the pump 20 up to a collection tank 24for drilling fluid on the deck 4. A tank 26A for a riser fluidcommunicates with the riser section 12 via a connecting pipe 28 at thedeck 4. The connecting pipe 28 may have a volume meter (not shown).Preferably, the density of the riser fluid is less than that of thedrilling fluid, as explained above. The power supply for the subsea mudlift pump 20 is typically provided by an electrical cable (not shown)from the drilling rig 1, and the pressure at the inlet to the subsea mudlift pump 20 is selected from the drilling rig 1. The drilling fluid ispumped down through the drill string 16 in a manner that is known in theart, and returns to the deck 4 via an annulus 30 between the liner 14and the drill string 16. When the subsea mud lift pump 20 is started,the drilling fluid is returned from the annulus 30 via the subsea mudlift pump 20 to the collection tank 24 on the deck 4.

While the embodiment shown in FIG. 1 has the subsea mud lift pump 20disposed near or on the water bottom 8, it should be understood that thesubsea mud lift pump may be placed at any intermediate position alongthe return line 22. Thus, the depth of the subsea mud lift pump 20 inthe body of water is not a limitation on the scope of the presentinvention.

The volume of fluid flowing into and out of the tank 26 is typicallymonitored, making it possible to determine, e.g., whether drilling fluidis being lost into an exposed formation (i.e., one not sealed by theliner 14), or whether gas or liquid is flowing from an exposed formationand into the wellbore 15 and fluid circulation system.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows an example mud lift or dual gradient drilling system knownin the art.

FIG. 2 shows an example ejector assembly mud lift drilling system.

FIG. 3 shows example embodiments of pump connections that may be used invarious embodiments.

FIG. 4 shows an example ejector assembly in more detail.

FIG. 5 shows another embodiment wherein an annular seal is used to sealan annular space between the drill string and the riser.

FIG. 6 shows an example of a retrievable ejector disposed in a fluidreturn line.

DETAILED DESCRIPTION

As explained in the Background section herein, most lifting devices thatperform the function of the subsea mud lift pump (20 shown in FIG. 1)are either constant lift/constant head pumps in the form of acentrifugal pump or are positive displacement pumps operated byhydraulic pressure or an electric motor. An example mud lift device willnow be described with reference to FIGS. 2 and 3 that may be directlydriven by a power fluid and which has no moving parts. Certaincomponents of the drilling system shown in FIG. 1 have been omitted fromFIGS. 2 and 3 for the sake of clarity.

In some embodiments, a drilling riser 14 may extend from a wellhead BOPElocated on the bottom 8 of a body of water and may extend to a drillingplatform 4 at the water surface as explained with reference to FIG. 1. Adrill string 16 may have drilling tools at a bottom end thereof of typesknown in the art, generally terminated by a drill bit 16A which may berotated by means not shown to extend the length of a wellbore 15.Drilling fluid may be pumped into an interior of the drill string 16 bya pump (26 in FIG. 3). During drilling, the drilling fluid may leave thewellbore 15 and enter the base of the riser 14. A fluid outlet 14C maybe provided in the riser 14 at a selected depth above the wellhead BOPEand below the drilling platform 4. A jet assembly or ejector assembly Dmay be included in a drilling fluid return path extending from the fluidoutlet 14C to the base of a fluid return line 22B. The fluid return line22B may extend to the drilling platform 4. In some embodiments such asshown in FIG. 2, the fluid return 22B line may extend substantiallyvertically to the drilling platform 4 to enable retrieval andreplacement of the ejector assembly D using, for example wireline orslickline if required. The structure of the fluid return line 22B inother embodiments may be other than vertical or substantially vertical.A power fluid line 22A may extend from the drilling platform 4 to apower fluid inlet of the ejector assembly D. Power fluid, which may bethe same fluid as the drilling fluid, may be pumped into the power fluidline 22A from a separate pump on the drilling platform (see 26B in FIG.3) or may have some of the discharged fluid from the drilling fluid pump(see 26 in FIG. 3) diverted into the power fluid line 22A.

In the present example embodiment, a pressure sensor C may be inpressure communication with the interior of the drilling riser 14 at aselected position. The pressure sensor C may be in signal communicationwith a pump controller (not shown separately) which may selectivelyoperate the power fluid pump (26B in FIG. 3) or a diverter valve (notshown) to selectively divert an amount of flow from the drilling fluidpump (26 in FIG. 3). In either of the foregoing example embodiments, arate of flow of power fluid into the power fluid inlet of the ejectorassembly D may be controlled so that a selected pressure in the drillingriser 14 is measured by the pressure sensor C. By such control over thepressure measured by the pressure sensor C and with knowledge of thehydrostatic and hydrodynamic properties of the drilling fluid, aselected pressure gradient may be maintained within the drilling riser14 and the wellbore 15 outside the drill string 16. In some embodiments,a variable flow restriction such as a controllable orifice choke 23 orsimilar controllable flow restrictor may be used at any selectedposition in the flow path between the wellbore fluid outlet and theworking fluid inlet of the ejector assembly D so that the ejectorassembly D may be operated at a substantially constant power fluid flowrate and fluid level in the riser 14 and resulting wellbore pressure maybe controlled by controlling the controllable orifice choke 23.

In some embodiments, a booster line 14A may be included alongside thedrilling riser 14 for injecting fluid when required, for example, suchas when necessary to circulate out a fluid that may enter the wellbore15 from a sub-bottom formation.

In other implementations, the riser 14 may be omitted, and drillingfluid being discharged from the wellbore 15 may be returned to thesurface by a separate return line having an ejector assembly therein.Such return line may be hydraulically connected to the wellbore belowthe wellhead (BOPE in FIG. 2) or above the wellhead. In suchimplementations, the power fluid line (22A in FIG. 2) may extend to thedepth at which the ejector assembly D is disposed. In embodiments thatdo not use a riser, an annular space between the drill string and thewellbore (15A in FIG. 2) may be hydraulically closed using a sealingelement such as a rotating control head, rotating blowout preventer orrotating diverter. Other “riserless” embodiments may simply have theannular space (15A in FIG. 2) open at an upper end thereof.

FIG. 3 shows one example implementation in which a separate drillingfluid pump 26, power fluid pump 26B and booster line pump 26C may bedisposed on the drilling platform 4. All three separate pumps 26, 26B,26C may withdraw drilling fluid from the tank 26A. In other embodiments,each pump 26, 26B, 26C may have a separate fluid supply tank.

An example ejector assembly D is shown in more detail in FIG. 4. Theejector assembly D may include a diffuser comprising a converging inletdiffuser D3 and a diverging outlet diffuser D4. An outlet of the outletdiffuser D4 may be coupled to the fluid return line (22B in FIG. 2). Aworking fluid inlet D1 to the ejector assembly D may be in fluidcommunication with the wellbore fluid outlet (e.g., riser outlet 14C inFIG. 2). Power or motive fluid pumped through the power fluid line 22Amay enter the ejector assembly D through a power fluid inlet. The powerfluid is discharged in the interior of the ejector assembly D upstreamof the converging diffuser D3 through a nozzle D2. The nozzle D2 servesto increase velocity of the power fluid so as to reduce fluid pressureat the working fluid inlet D1. A combination of the power fluid and theworking fluid, e.g., the drilling fluid, maybe returned to the drillingplatform (4 in FIG. 2) through the fluid return line (22B in FIG. 2).

Another embodiment shown in FIG. 5 may include a seal 16A disposed inthe annular space between the interior of the riser 14 and the exteriorof the drill string 16. In some embodiments, the seal 16A may be arotatable seal such as a rotating control head, rotating diverter orrotating control device of any type known in the art. In the embodimentshown in FIG. 5, the seal 16A may generally be disposed axially abovethe position of the fluid outlet 14C. In some embodiments, the seal 16Amay be disposed proximate the drilling platform 4. The exact position ofthe seal 16A is not intended to limit the scope of the presentdisclosure. In embodiments such as shown in FIG. 5, a rate of pumpingfluid into the power fluid injection line 22A may be selected to providea selected fluid pressure at the riser outlet 14C independently of fluidpressure in the riser 16 above the seal 16A.

FIG. 6 shows an example of an ejector D that may be replaced without theneed to disconnect any components of the power fluid injection line (22Ain FIG. 5) or the fluid return line (22B in FIG. 5). The ejector D mayinclude a latch 52 of types well known in the art for mating withcorresponding locking features 52A in the interior of the fluid returnline 22B. For example, the locking features may comprise collets ortangs that may be radially compressed when upward force is applied to afishing neck 50, such as by using an “overshot” coupled to the end of awireline, slickline, spoolable tube or other conveyance mechanism knownin the art. A seal 54 may be disposed on the exterior of the ejector Dto prevent movement of fluid between the exterior of the ejector D andthe interior of the fluid return line 22B. The riser outlet 14C may bein fluid connection with the interior of the fluid return line 22B suchthat irrespective of the rotational orientation of the ejector D, theworking fluid inlet (D1 in FIG. 4) is in fluid communication with theriser outlet 14C. Fluid from the power fluid injection line (22A in FIG.5) may enter the ejector D from the bottom thereof as shown in FIG. 6.If during operation of a system using an ejector D such as shown in FIG.6, the ejector becomes worn or damaged, or if the fluid transportproperties of the ejector D require changing the ejector, the fluidreturn line 22B may be opened from the surface, and an overshot (notshown in the Figures) may be lowered into the fluid return line 22B suchas by extending a wireline, slickline, coiled tubing or semi-stiffspoolable rod into the fluid return line 22B. After latching onto thefishing neck 50, the entire ejector D may be removed from the fluidreturn line 22B and a replacement ejector may be inserted therein bylowering the replacement ejector into the fluid return line 22B andallowing the latching mechanism 52 to engage the locking features 52Atherein.

A mud lift drilling system and method according to the presentdisclosure may provide the capability of controlling wellbore pressurewithout the need for a pump having moving parts disposed below thesurface of a body of water. Embodiments of an ejector assembly accordingto the present disclosure may be replaceable by a wireline or slicklineoperation, or using a coiled tubing or semi-stiff spoolable interventionrod thus simplifying ejector assembly replacement if and when needed. Asemi-stiff, spoolable intervention rod and deployments is available fromZiebel, AS, Stavanger, Norway under the registered trademark Z-LINE.

While the invention has been described with respect to a limited numberof embodiments, those skilled in the art, having benefit of thisdisclosure, will appreciate that other embodiments can be devised whichdo not depart from the scope of the invention as disclosed herein.Accordingly, the scope of the invention should be limited only by theattached claims.

What is claimed is:
 1. A method for controlling pressure in a wellboredrilled below the bottom of a body of water, the wellbore having a fluidoutlet in fluid communication with a working fluid inlet of an ejectorassembly to return drilling fluid to a drilling platform on the watersurface, the method comprising: pumping drilling fluid into a drillstring extending from the drilling platform into the wellbore; and atleast one of, (i) introducing fluid into a power fluid inlet of theejector assembly at a rate selected to remove fluid from the wellbore ata selected rate and (ii) operating a controllable flow restriction in afluid path from the wellbore to the working fluid inlet of the ejectorassembly, to maintain a selected wellbore pressure.
 2. The method ofclaim 1 wherein the maintaining the selected wellbore pressure comprisesmaintaining a fluid level in a riser extending from a wellhead disposedon the bottom of the body of water to a drilling platform above thewater surface.
 3. The method of claim 1 further comprising removing theejector assembly from a fluid return line extending from the drillingplatform using at least one of a wireline, slickline, coiled tubing anda semi-stiff spoolable intervention rod extended into the fluid returnline.
 4. The method of claim 1 further comprising sealing an annularspace between the drill string and an interior of a drilling riserextending from a wellhead proximate the bottom of the body of water toproximate the drilling platform.
 5. A wellbore drilling systemcomprising: a drill string extending into the wellbore from a drillingplatform at a surface of a body of water; a fluid pump coupled to aninterior passage in the drill string; a fluid outlet connected to thewellbore, the fluid outlet in fluid communication with a working fluidinlet of an ejector assembly, an outlet of the ejector assembly in fluidcommunication with a fluid return line extending to the drillingplatform; a pressure sensor in pressure communication with an interiorof the wellbore; and means for pumping a power fluid into an inlettherefor in the ejector assembly, the means for pumping controllable inresponse to signals from the pressure sensor to enable maintaining aselected wellbore pressure.
 6. The wellbore drilling system of claim 5further comprising a variable flow restriction between the fluid outletand the ejector assembly.
 7. The wellbore drilling system of claim 5further comprising a riser extending from the bottom of the body ofwater to the drilling platform and wherein the pressure sensor is influid communication with an interior of the riser.
 8. The wellboredrilling system of claim 5 wherein the fluid return line issubstantially vertical and the ejector assembly is disposed in the fluidreturn line such that the ejector assembly is removable from the fluidreturn line by at least one of a wireline, slickline, coiled tubing anda semi-stiff spoolable intervention rod extended into the fluid returnline.
 9. The wellbore drilling system of claim 5 further comprising aseal disposed in an annular space between the drill string and aninterior of a drilling riser extending from a wellhead proximate abottom of a body of water to proximate the drilling platform.